SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Fiscal Year Ended Dec. 31, 2000 Commission File Number 1-3034
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
(State of other jurisdiction of incorporation of (I.R.S. Employer Identification No)
800 Nicollet Mall, Minneapolis, Minnesota 55402
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (612) 330-5500
Northern States Power Company
414 Nicollet Mall, Minneapolis, Minnesota 55401
Former name, former address and former fiscal year, if changed since last report
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
Xcel Energy Inc. . . . . . . . . . . . . . . . Common Stock, $2.50 par value per share New York, Chicago, Pacific
Xcel Energy Inc. . . . . . . . . . . . . . . . Cumulative Preferred Stock, $100 Par Value New York
Xcel Energy Inc. . . . . . . . . . . . . . . . Preferred Stock $3.60 Cumulative New York
Xcel Energy Inc. . . . . . . . . . . . . . . . Preferred Stock $4.08 Cumulative New York
Xcel Energy Inc. . . . . . . . . . . . . . . . Preferred Stock $4.10 Cumulative New York
Xcel Energy Inc. . . . . . . . . . . . . . . . Preferred Stock $4.11 Cumulative New York
Xcel Energy Inc. . . . . . . . . . . . . . . . Preferred Stock $4.16 Cumulative New York
Xcel Energy Inc. . . . . . . . . . . . . . . . Preferred Stock $4.56 Cumulative New York
Securities registered pursuant to Section 12(g) of Act: None
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants
were required to file such reports), and (2) have been subject to such filing requirements for the past
90 days. Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
As of March 15, 2001, the aggregate market value of the voting common stock held by non-affiliates of the
Registrant was $9,605,563,141 and there were 342,441,953 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant’s Definitive Proxy Statement for its Annual Meeting of Shareholders, to be held April 25, 2001, are
incorporated by reference into Part III of this Form 10-K.
On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Co. (NSP)
merged and formed Xcel Energy Inc. Xcel Energy, a Minnesota corporation, is a registered holding
company under the Public Utility Holding Company Act (PUHCA). Each share of NCE common stock
was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares
on a one-for-one basis. The merger was structured as a tax-free, stock-for-stock exchange for
shareholders of both companies (except for fractional shares), and accounted for as a
pooling-of-interests. As part of the merger, NSP transferred its existing utility operations that were
being conducted directly by NSP at the parent company level to a newly formed subsidiary of Xcel
Energy named Northern States Power Company.
Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12
states. These six utility subsidiaries are Northern States Power Company, a Minnesota corporation
(NSP-Minnesota), Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), Public
Service Company of Colorado (PSCo), Southwestern Public Service Company (SPS), Black Mountain
Gas Company (BMG) and Cheyenne Light, Fuel and Power Company (Cheyenne). Their service
territories include portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North
Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Xcel Energy’s regulated businesses
also include Viking Gas Transmission Company and WestGas InterState Inc. (WGI), both interstate
natural gas pipeline companies.
Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of
which is NRG Energy, Inc., a publicly traded independent power producer. At Dec. 31, 2000, Xcel
Energy indirectly owned 82 percent of NRG. Xcel Energy owned 100 percent of NRG until the second
quarter of 2000, when NRG completed its initial public offering. During March 2001, NRG issued an
additional 18.4 million shares of common stock, which caused Xcel Energy’s ownership interest in NRG
to decline to approximately 75 percent. For more information, see NRG Initial Public Offering
discussed under Liquidity and Capital Resources in Management’s Discussion and Analysis under
In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Seren Innovations, Inc.
(broadband telecommunications services), e prime, inc. (natural gas marketing and trading), Planergy
International Inc. (energy management, consulting and demand-side management services) and Eloigne
Company (acquisition of rental housing projects that qualify for low-income housing tax credits). Xcel
Energy also reports in its nonregulated activities its 50-percent stake in Yorkshire Power, a regional
electricity company in the United Kingdom. Subsequent to year-end, Xcel Energy has agreed to sell a
substantial portion of this investment. For more information, see Note 11 to the Financial Statements
under Item 8.
Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate
holding companies with additional subsidiaries: Xcel Energy Wholesale Group, Inc., Xcel Energy
Markets Holdings Inc., Xcel Energy International Inc., Xcel Energy Ventures Inc., Xcel Energy Retail
Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc., Xcel Energy O&M
Services Inc. and Xcel Energy Services Inc. Xcel Energy and its subsidiaries collectively are referred to
as Xcel Energy.
Xcel Energy was incorporated under the laws of Minnesota in 1909. Its executive offices are
located at 800 Nicollet Mall, Minneapolis, Minnesota 55401.
For information on the nonregulated subsidiaries of Xcel Energy, see Nonregulated Subsidiaries
under Item 1. For information regarding Xcel Energy’s segments and foreign revenues, see Note 18 to
the Financial Statements under Item 8.
NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an
operating utility engaged in the generation, transmission and distribution of electricity and the
transportation, storage and distribution of natural gas. NSP-Minnesota provides generation,
transmission and distribution of electricity in Minnesota, North Dakota and South Dakota.
NSP-Minnesota also purchases, distributes and sells natural gas to retail customers and transports
customer-owned gas in Minnesota, North Dakota and South Dakota. NSP-Minnesota provides retail
electric utility service to approximately 1.3 million customers and gas utility service to approximately
0.4 million customers.
NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds
real estate; First Midwest Auto Park Inc., which owns and operates a parking ramp; NSP Nuclear
Corp., which holds NSP-Minnesota’s interest in the Nuclear Management Company; and NSP
Financing I, a special purpose business trust.
NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an
operating utility engaged in the generation, transmission and distribution of electricity to approximately
225,000 retail customers in northwestern Wisconsin and in the western portion of the Upper Peninsula
of Michigan. NSP-Wisconsin is also engaged in the distribution and sale of natural gas in the same
service territory to approximately 90,000 customers in Wisconsin and Michigan.
NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement
Company, which operates hydro reserves; Clearwater Investments Inc., which owns interests in
affordable housing; and NSP Lands, Inc., which holds real estate.
PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged
principally in the generation, purchase, transmission, distribution and sale of electricity and the
purchase, transportation, distribution and sale of natural gas. PSCo serves approximately 1.2 million
electric customers and approximately 1.1 million gas customers in Colorado.
PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate
interests of PSCo; P.S.R. Investments, Inc., which owns and manages permanent life insurance policies
on certain employees; PS Colorado Credit Corporation, a finance company that finances certain of
PSCo’s current assets; and Green and Clear Lakes Company, which owns water rights. PSCo also holds
a controlling interest in several other relatively small ditch and water companies whose capital
requirements are not significant.
SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged
primarily in the generation, transmission, distribution and sale of electricity. SPS serves approximately
390,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale
customers served by SPS comprise approximately 34 percent of the total kilowatt-hour sales.
Other Regulated Subsidiaries
Cheyenne was incorporated in 1900 under the laws of Wyoming. Cheyenne is an operating utility
engaged in the purchase, transmission, distribution and sale of electricity and natural gas primarily
serving approximately 36,000 electric customers and 29,000 natural gas customers in and around
BMG was incorporated in 1999 under the laws of Minnesota. BMG is a natural gas and propane
distribution company, located in Cave Creek, Ariz., with approximately 6,500 customers.
Viking Gas, acquired in 1993, owns and operates an interstate natural gas pipeline serving portions
of Minnesota, Wisconsin and North Dakota. Viking operates exclusively as a transporter of natural gas
for third-party shippers under authority granted by the Federal Energy Regulatory Commission
WGI was incorporated in 1990 under the laws of Colorado. WGI is a natural gas transmission
company engaged in transporting gas from Chalk Bluffs, Colo., to Cheyenne, Wyo.
The Xcel Energy system is subject to the jurisdiction of the Securities and Exchange Commission
(SEC) under PUHCA. The rules and regulations under PUHCA generally limit the operations of a
registered holding company to a single integrated public utility system, plus additional energy-related
businesses. PUHCA rules require that transactions between affiliated companies in a registered holding
company system be performed at cost, with limited exceptions.
The FERC has jurisdiction over wholesale rates for electric transmission service and electric energy
sold in interstate commerce, hydro facility licensing, the wholesale gas transportation rates of Viking,
the siting and construction of facilities by Viking and certain other activities of Xcel Energy’s utility
subsidiaries. Federal, state and local agencies also have jurisdiction over many of Xcel Energy’s other
Xcel Energy is unable to predict the impact on its operating results from the future regulatory
activities of any of these agencies. Xcel Energy strives to comply with all rules and regulations issued by
the various agencies.
Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the
jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service
Commission (NDPSC) and the South Dakota Public Utilities Commission (SDPUC) within their
respective states. The MPUC also possesses regulatory authority over aspects of NSP-Minnesota’s
financial activities, including security issuances, certain property transfers, mergers with other utilities
and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and
approves NSP-Minnesota’s electric resource plans and gas supply plans for meeting customers’ future
The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites
for new power plants with a capacity of 50 megawatts or more and wind energy conversion plants with
a capacity of five megawatts or more. It also designates routes for electric transmission lines with a
capacity of 200 kilovolts (kv) or more. No power plant or transmission line may be constructed in
Minnesota except on a site or route designated by the MEQB.
NSP-Wisconsin is subject to regulation of similar scope by the Public Service Commission of
Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). In addition, each of the
state commissions certifies the need for new generating plants and electric and retail gas transmission
lines of designated capacities to be located within the respective states before the facilities may be sited
The PSCW has a biennial filing requirement. By June of each odd-numbered year, NSP-Wisconsin
must submit rate filings for calendar years beginning the following January. The filing procedure and
review generally allow the PSCW sufficient time to issue an order effective with the start of the test
PSCo is subject to the jurisdiction of the Colorado Public Utility Commission (CPUC) with respect
to its facilities, rates, accounts, services and issuance of securities. PSCo is subject to the jurisdiction of
the FERC with respect to its wholesale electric operations and accounting practices and policies. PSCo
has received authorization from the FERC to act as a power marketer. Also, PSCo holds a FERC
certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject
to full FERC jurisdiction.
The Public Utility Commission of Texas (PUCT) has jurisdiction over SPS’ Texas operations as an
electric utility and original and appellate jurisdiction over its retail rates and services. The New Mexico
Public Regulatory Commission (NMPRC) has jurisdiction over the issuance of securities and
accounting. The NMPRC, the Oklahoma Corporation Commission and the Kansas Corporation
Commission have jurisdiction with respect to retail rates and services in their respective states. The
FERC has jurisdiction over SPS’ rates for sales for resale and the transmission of electricity in
Cheyenne is subject to the jurisdiction of the Wyoming Public Service Commission (WPSC) with
respect to its facilities, rates, accounts, services and issuance of securities. All electric demand and
purchased power costs are recoverable through an energy adjustment clause. Differences in costs
incurred from costs recovered in rates are deferred and recovered through prospective adjustments to
rates. However, rate changes for cost recovery require WPSC approval before going into effect.
Historically, customers have been provided carrying costs on overcollected costs, but Cheyenne has not
been allowed to collect carrying charges for under recovered costs.
Viking and WGI are subject to FERC jurisdiction and each holds a FERC certificate, which allows
them to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas
Act.. BMG is subject to the Arizona Corporation Commission (ACC).
Fuel, Purchased Gas and Resource Adjustment Clauses
NSP-Minnesota’s retail electric rate schedules provide for adjustments to billings and revenues for
changes in the cost of fuel and purchased energy. NSP-Minnesota is permitted to recover option costs
through a fuel clause adjustment, a mechanism that allows NSP-Minnesota to bill customers for the
actual cost of fuel used to generate electricity at its plants and energy purchased from other suppliers.
Changes in capacity charges are not recovered through the fuel clause. NSP-Minnesota’s electric
wholesale customers do not have a fuel clause provision in their contracts. Instead, the contracts have
an escalation factor.
Gas rate schedules for NSP-Minnesota include a purchased gas adjustment (PGA) clause that
provides for rate adjustments for changes in the current unit cost of purchased gas compared with the
last costs included in rates. The PGA factors in Minnesota are calculated for the current month based
on the estimated purchased gas costs for that month.
By September of each year, NSP-Minnesota is required to submit to the MPUC an annual report
of the PGA factors used to bill each customer class by month for the previous year commencing July 1
and ending June 30. The report verifies whether the utility is calculating the adjustments properly and
implementing them in a timely manner. In addition, the MPUC reviews procurement policies,
cost-minimizing efforts, rule variances, retail transportation gas volumes, independent auditors’ reports
and the impact of market forces on gas costs for the coming year. The MPUC has the authority to
disallow certain costs if it finds the utility was not prudent in its gas procurement activities.
NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota
electric revenue and 0.5 percent of Minnesota gas revenue on conservation improvement programs
(CIP). These costs are recovered through an annual recovery mechanism for electric and gas
conservation and energy management program expenditures. NSP-Minnesota is required to request a
new cost recovery level annually.
NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail
customers. Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs
with those costs that were included in the latest retail electric rates. If the comparison results in a
difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise
rates. Any revised rates would be effective until the next rate case. The adjustment approved is
calculated on an annual basis, but applied prospectively. Most of NSP-Wisconsin’s wholesale electric
rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and
During 1999, the PSCW approved a new gas cost recovery mechanism to replace the PGA. The
financial impact of the gas cost recovery mechanism is substantially the same as with the former PGA.
NSP-Wisconsin’s gas and retail electric rate schedules for Michigan customers include gas cost
recovery factors and power supply cost recovery factors, which are based on 12-month projections.
After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and
any under-collections are collected from the customers.
PSCo has five adjustment clauses: the incentive cost adjustment (ICA), the gas cost adjustment
(GCA), the steam cost adjustment (SCA), the demand side management cost adjustment (DSMCA)
and the qualifying facilities capacity cost adjustment (QFCCA). These adjustment clauses allow certain
costs to be passed through to retail customers. PSCo is required to file applications with the CPUC for
approval of adjustment mechanisms in advance of the proposed effective dates. The applications must
be acted upon before becoming effective.
The ICA allows for an equal sharing between customers and shareholders of certain fuel and
energy cost increases. PSCo, through its GCA, is allowed to recover its actual costs of purchased gas.
The GCA rate is revised annually in October, and otherwise as needed, to coincide with changes in
purchased gas costs. Purchased gas costs and revenues received to recover such gas costs are compared
on a monthly basis and differences are deferred. PSCo, through its SCA, is allowed to recover the
difference between its actual cost of fuel and the amount of these costs recovered under its base rates.
The SCA rate is revised annually in January, and otherwise as needed, to coincide with changes in fuel
costs. The QFCCA provides for recovery of purchased capacity costs from certain QF projects not
otherwise reflected in base electric rates.
The DSMCA clause currently permits PSCo to recover DSM costs over five years while non-labor
incremental expenses and carrying costs associated with deferred DSM costs are recovered on an
annual basis. PSCo also has implemented a low-income energy assistance program. The costs of this
energy conservation and weatherization program for low-income customers are recovered through the
Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part
of SPS’ rates. If it appears that SPS will materially over-recover or under-recover these costs, the factor
may be revised upon application by SPS or action by the PUCT. The rule requires refunding and
surcharging under/over-recovery amounts, including interest, when they exceed 4 percent of the utility’s
annual fuel and purchased power costs, as allowed by the PUCT, if this condition is expected to
continue. PUCT regulations require periodic examination of SPS fuel and purchased power costs, the
efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and
purchase power commitments. Under the PUCT’s regulations, SPS is required to file an application for
the PUCT to retrospectively review at least every three years the operations of SPS’ electric generation
and fuel management activities.
The NMPRC regulations provide for a fuel and purchased power cost adjustment clause and a
fixed annual fuel factor for SPS’ New Mexico retail jurisdiction. SPS files monthly and annual reports
of its fuel and purchased power costs with the NMPRC, which include the current over/under fuel
collection calculation, plus interest. In addition, SPS revises its fixed fuel factor annually to recover
projected fuel and purchased power costs as well as any over/under cost balance for the current year.
SPS is required to petition for a change in the fixed fuel factor if the over/under recovery balance
reaches $5 million.
Conservation Recovery—NSP-Minnesota had a 4.1 percent conservation rate surcharge in place since
1998, pending resolution of the conservation incentive recovery issue. On July 31, 2000, the MPUC
approved NSP-Minnesota’s request to prospectively reduce the surcharge level to 0.68 percent
(consistent with current costs to be recovered) and to refund cumulative overcollections of
approximately $24 million. The refund occurred during December 2000. Although cash flows were
reduced, NSP-Minnesota did not have any earnings impact from these actions due to accruals
previously recorded. For more information, see Management’s Discussion and Analysis under Item 7.
Fuel Clause Adjustment—In June 2000, the MPUC approved a change under which bills received by
NSP-Minnesota’s electricity customers will more accurately reflect energy costs on a timely basis.
Previously, the adjustment reflected prior period costs, and it would take approximately three months
for customer bills to reflect higher, or lower, fuel costs incurred by NSP-Minnesota. Under the new
method, NSP-Minnesota bases the customer billing adjustment on projected energy costs for the
current month, and corrects, in a subsequent month, any differences between projected costs and actual
costs incurred. This improved matching between costs and usage should encourage customers to take
appropriate steps to reduce energy use during peak periods—when costs are at their highest—while
giving appropriate price signals when costs are lower during off-peak periods. NSP-Minnesota
implemented the revised fuel clause adjustment with July 2000 billings.
Energy Cost Recovery—In April 2000, the Minnesota Office of Attorney General (OAG) filed a
petition with the MPUC asking the MPUC to initiate an investigation of NSP-Minnesota’s fuel and
purchased energy cost recoveries under the FCA provisions of NSP’s tariffs. The OAG alleged
NSP-Minnesota could be improperly diverting low-cost NSP-Minnesota generation supplies to the
wholesale market to increase profits, while recovering higher-cost energy purchases through the FCA.
NSP-Minnesota contends that it has followed the appropriate FCA rules and regulations. In July 2000,
the MPUC issued an order in which it indicated that the record before the MPUC did not reflect any
specific allegations of wrongdoing. However, the MPUC instructed NSP-Minnesota and the OAG to
resolve any concerns and file a report with the MPUC. The report is pending.
North Dakota Rate Case—In October 2000, NSP-Minnesota filed a request with the NDPSC to
increase natural gas rates by approximately 3.3 percent, or $1.4 million, annually. Evidentiary hearings
are scheduled for April 2001 with an order likely during the second quarter of 2001.
Temporary Fuel Cost Surcharge—In May 2000, the PSCW issued an order granting a fuel surcharge
to increase electric rates to recover higher fuel costs. The increase was primarily the result of higher
purchased power costs than were anticipated in base rates. The surcharge factor increased revenues by
approximately $6.4 million in 2000 and represented an average increase for all customer classes of
approximately 2 percent. The surcharge factor is expected to be effective through Dec. 31, 2001.
Gas Rate Case—In July 2000, PSCo filed a retail rate case with the CPUC requesting an annual
increase in its gas revenues of approximately $40 million. The request for a rate increase reflects
revenues for additional plant investment, a 12.5-percent return on equity, new depreciation rates and
recovery of the dismantlement costs associated with the Leyden Gas Storage facility. In February 2001,
the CPUC granted an increase in gas revenues of $14.2 million and authorized an 11.25-percent return
on equity. The CPUC did not grant the new depreciation rates proposed by PSCo, but rather granted
new depreciation rates proposed by the CPUC staff. The CPUC denied recovery of the dismantlement
costs associated with the Leyden Gas Storage facility in this case and recommended PSCo request
recovery in a later case.
Fuel Recovery—At least every three years, SPS is required to file an application for the PUCT to
retrospectively review the operations of a utility’s electricity generation and fuel management activities.
In June 2000, SPS filed an application for the PUCT to retrospectively review the operations of the
utility’s electricity generation and fuel management activities. In this application, SPS filed its
reconciliation for generation and fuel management activities totaling approximately $419 million, for
the period from January 1998 through December 1999. SPS expects to be granted recovery of these
costs. Final approval is pending.
SPS filed an application in July 2000 seeking to increase its fixed fuel factors as a result of recent
increases in natural gas costs. In August 2000, SPS filed a second application seeking authority to
surcharge approximately $26 million in fuel under-recoveries and related interest accrued through the
June 2000 billing cycle over the eight months ending May 2001. In August 2000, the PUCT
consolidated these two filings into one docket. SPS reached a unanimous stipulation with all parties to
the case resolving all outstanding issues. This stipulation was approved by the PUCT in
September 2000, which allowed the new fuel factors and surcharge factors to become effective in the
October 2000 billing cycle.
In October 2000, SPS filed an unopposed motion with the NMPRC, seeking to change the date for
the implementation of its next fixed annual fuel factor. SPS was approximately $12.8 million under-
collected in fuel and purchased power costs through August 2000 and projected that these under-
collections would continue based on recent increases in natural gas costs. In October 2000, the NMPRC
approved SPS’ revised fixed annual fuel factor to be effective in the November 2000 billing cycle.
In November 2000, SPS filed an application with the PUCT seeking authority to surcharge
approximately $43 million in fuel under recoveries and related interest accrued during July 2000
through September 2000. SPS reached a unanimous stipulation with all parties to the case resolving all
outstanding issues. In January 2001, the PUCT approved the surcharge and required amounts be
applied to customers bills over an eleven-month period starting February 2001.
On March 15, 2001, Cheyenne filed an application with the WPSC requesting approval to pass
through to electric customers an increase in the cost of electricity and transmission of $36 million for
the remainder of 2001. The increase is requested to be effective April 15, 2001. The application follows
a dramatic increase in Cheyenne’s contractual electric purchase costs. Normally, the full cost of these
increases are passed through to customers on a dollar-for-dollar basis. However, as part of its
application, Cheyenne has requested approval to defer recovery of approximately $61 million of
increased power costs for a period of five years. The WPSC has opened an investigation into the
proposed rate increased with hearings scheduled to begin April 2001. For more information on the
increase in Cheyenne’s purchase power costs, see Management’s Discussion and Analysis under Item 7.
For more information on regulatory matters, see Management’s Discussion and Analysis under
ELECTRIC UTILITY OPERATIONS
Competition and Industry Restructuring
Retail competition and the unbundling of regulated energy service could have a significant
financial impact on Xcel Energy and its subsidiaries, due to an impairment of assets, a loss of retail
customers, lower profit margins and increased costs of capital. The total impacts of restructuring may
have a significant financial impact on the financial position, results of operations and cash flows of Xcel
Energy. Xcel Energy and its utility subsidiaries cannot predict when they will be subject to changes in
legislation or regulation, nor can they predict the impacts of such changes on their financial position,
results of operations or cash flows. Xcel Energy believes that the prices its utility subsidiaries charge for
electricity and the quality and reliability of their service currently place them in a position to compete
effectively in the energy market.
Retail Business Competition—The retail electric business faces increasing competition as industrial
and large commercial customers have some ability to own or operate facilities to generate their own
electric energy. In addition, customers may have the option of substituting other fuels, such as natural
gas for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a
lower cost environment. While each of Xcel Energy’s utility subsidiaries face these challenges, these
subsidiaries believe their rates are competitive with currently available alternatives. Xcel Energy’s utility
subsidiaries are taking actions to lower operating costs and are working with their customers to analyze
energy efficiency, load management and cogeneration in order to better position Xcel Energy’s utility
subsidiaries to more effectively operate in a competitive environment.
Wholesale Business Competition—The wholesale electric business faces increasing competition in the
supply of bulk power, due to federal and state initiatives to provide open access to utility transmission
systems. Under current FERC rules, utilities are required to provide wholesale open-access
transmission services and to unbundle wholesale merchant and transmission operations. Xcel Energy’s
utility subsidiaries are operating under a joint tariff in compliance with these rules. To date, these
provisions have not had a material impact on the operations of Xcel Energy’s utility subsidiaries.
Minnesota Restructuring—During the summer of 2000, the Commerce Commissioner, Attorney
General, Senate Majority Leader and House Speaker all publicly identified the potential shortage in
electric supply as a critical issue for the coming legislative session. Each of these leaders expressed
hesitation about adopting a comprehensive restructuring proposal, but they acknowledged the need for
reforms in our power supply regulatory system. The Minnesota Chamber of Commerce still intends to
push for a comprehensive restructuring bill. Based on the recommendations made by the Department
of Commerce in their report ‘‘Keeping the Lights On,’’ it is likely that reform of utility taxation and
generation and transmission siting will be two of the issues debated by the 2001 Legislature.
North Dakota Restructuring—In 1997, the North Dakota Legislature established an Electric Utility
Committee charged with studying the impact of competition on the electric industry. The committee
has six years to study the impact of competition on the electric energy industry in the state. During
2000, the committee began the study of the current tax structure on the industry. The committee was
also given the responsibility for assessing the need for modifications to the Territorial Integrity Act, a
law governing distribution service territories within the state. The final report presented to the
legislative council made no recommendations to change the current tax structure at the present time.
The committee will resume its work after the 2001 legislative session.
In December 2000, the NDPSC approved Xcel Energy’s ‘‘PLUS’’ Performance Based Regulation
proposal, effective January 2001 for its electric operations in the state. The plan establishes
performance standards for reliability, customer service, price and employee safety. The company’s
performance determines its allowed return on equity. The plan also includes revenue sharing and a
price cap mechanism. The plan will remain in effect through 2005.
Wisconsin Restructuring—During 1999, Wisconsin state lawmakers passed ‘‘Reliability 2000’’
legislation, which included steps necessary to further progress toward a restructured industry, eventually
including allowing retail customers to choose their electric supplier. One of the provisions of the
legislation establishes a public benefits fund, to be administered by the State of Wisconsin, which will
use money collected from Wisconsin utilities’ customers to pay for low-income assistance, conservation
programs and renewable energy and environmental research programs. NSP-Wisconsin began collecting
the public benefits surcharge from its Wisconsin customers in October 2000.
In April 1998, Wisconsin state legislators enacted a law that includes provisions that require the
PSCW to order a public utility that owns transmission facilities in Wisconsin to transfer control of its
transmission facilities to an independent system operator (ISO) or divest its interest in its transmission
facilities to an independent transmission company (ITC) by June 2000. NSP-Minnesota and
NSP-Wisconsin joined the Midwest ISO (MISO) in 1999 and filed for PSCW and FERC approval in
March 2000. The MISO is not expected to be operational until November 2001. In June 2000, the
PSCW issued an order that effectively waived the deadline for the state’s five major utilities, including
NSP-Wisconsin, to relinquish transmission system control. In October 2000, the PSCW issued an order
authorizing NSP-Wisconsin’s transfer of operating control of its transmission system to the MISO.
Michigan Restructuring—In June 2000, Michigan’s ‘‘Customer Choice and Electricity Reliability
Act,’’ became law. The passage of the Act means there will be customer choice for all customers in
Michigan, including NSP-Wisconsin’s customers in the Upper Peninsula, starting January 2002. Key
elements of the law include developing distribution reliability and performance standards and
environmental and fuel disclosure standards, codes of conduct, customer and employee education
programs and an Upper Peninsula Market Power Study. The Act also contains a number of consumer
protection provisions dealing with cramming, slamming and low-income energy assistance.
NSP-Wisconsin filed its preliminary restructuring plan in October 2000 and revisions to the preliminary
restructuring plan in February 2001. NSP-Wisconsin expects to file its unbundled rates by June 2001.
The five-percent rate reduction and rate freeze ordered in the Act does not apply to NSP-Wisconsin or
other utilities with less than 1 million customers in Michigan.
Colorado Restructuring—During 1998, a bill was passed in Colorado that established an advisory
panel to conduct an evaluation of electric industry restructuring and customer choice. During 1999, this
panel concluded that Colorado would not significantly benefit from opening its markets to retail
New Mexico Restructuring—In April 1999, New Mexico enacted the Electric Utility Restructuring
Act of 1999, which provides for customer choice. The legislation provides for recovery of no less than
50 percent of stranded costs for all utilities. Transition costs must be approved by the NMPRC prior to
being recovered through a non-bypassable wires charge, which must be included in transition plan
filings. SPS must separate its utility operations into at least two entities: energy generation and
competitive services, and transmission and distribution utility services, either by the creation of separate
affiliates that may be owned by a common holding company or by the sale of assets to one or more
third parties. A regulated company, in general, is prohibited from providing unregulated services. In
May 2000, the NMPRC approved:
• customer choice for residential, small commercial and educational customers by January 2002;
• customer choice for commercial and industrial customers by July 2002; and
• completion of SPS corporate separation by August 2001.
The NMPRC has reopened its electric restructuring rulemakings to consider the impacts on New
Mexico electricity markets arising from the volatile California electricity market conditions. In addition,
in February 2001, the New Mexico Senate approved a bill that would delay the implementation of
restructuring and retail choice until 2007. The House has yet to act on the proposal to delay. We
cannot predict the changes that may result from reconsideration of the restructuring legislation or the
NMPRC’s reconsideration of its regulations as a result of the continuing and significant conditions in
the California markets.
Texas Restructuring—In June 1999, an electric utility restructuring act (SB-7) was passed in Texas,
which provides for the implementation of retail competition for most areas of the state, including SPS’
service area, beginning January 2002. The PUCT can delay the date for full retail competition if a
power region is unable to offer fair competition and reliable service during the 2001 pilot projects. The
• a rate freeze for all customers until January 2002;
• an annual earnings test through 2001;
• a 6-percent rate reduction for those residential and small commercial customers who choose not
to switch suppliers at the start of retail competition;
• the unbundling of business activities, costs and rates relating to generation, transmission and
distribution, and retail services;
• reductions in nitrogen oxide and sulfur dioxide emissions; and
• the recovery of stranded costs.
SB-7 requires each utility to unbundle its business activities into three separate legal entities: a
power generation company, a regulated transmission and distribution company, and a retail electric
provider. SB-7 limits the market share that a single generation provider can control to 20 percent of
the generating capacity within a qualified power region. The establishment of a qualified power region
with multiple generation suppliers is required under SB-7 in order to implement full retail competition.
SPS must return any excess earnings indicated in the annual earnings tests above its last allowed rate of
return for 1999, 2000 and 2001 or alternatively may direct any excess earnings to improvements in
transmission and distribution facilities, to capital expenditures to improve air quality or to accelerate
the amortization of regulatory assets, subject to PUCT approval.
The Texas Legislature is currently considering amendments to SB-7 that would delay the
implementation of business separation and customer choice in SPS’ market area for five years.
For more information on restructuring in Texas and New Mexico, see Note 12 to the Financial
Statements under Item 8.
Kansas Restructuring—In 1999, the Kansas Corporation Commission investigated the adequacy of
generation capacity of Kansas utilities. The Commission ordered the staff to continually monitor the
generation capacity situation in Kansas, ensure the regular filing of information by utilities to meet
their responsibility to provide electric service to retail customers and consider the opening of a new
docket for conservation appeals.
Oklahoma Restructuring—The Electric Restructuring Act of 1997 was enacted in Oklahoma during
1997. This legislation directs a series of studies, which will define the orderly transition to consumer
choice of electric energy supplier by July 1, 2002. The Electric Restructuring Act was modified during
1998 to clarify terms used in the original bill, as well as advance timelines for studies of the Joint
Electric Utility Task Force in order to meet the stated implementation date. In 1998, this task force
began the formation of groups, which will examine numerous restructuring issues. A report was issued
in 1999. The 2001 legislative session will consider the task force’s findings as it considers issues related
to implementing customer choice in 2002.
Wyoming Restructuring—There were no electric industry restructuring legislation proposals
introduced in the Legislature during 2000. No action with respect to electric restructuring is anticipated
Capacity and Demand
Assuming normal weather during 2001, system peak demand and the net dependable system
capacity for Xcel Energy’s electric utility subsidiaries are projected below. The electric production and
transmission system of NSP-Minnesota and NSP-Wisconsin are managed as an integrated system
(referred to as the NSP System). The system peak demand for each of the last three years and the
forecast for 2001 is listed below.
System Peak Demand (Mw)
Operating company 1998 1999 2000 2001
NSP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,660 7,990 7,936 7,747
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,771 4,854 5,406 5,519
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,933 3,937 3,870 3,583
Cheyenne . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140 144 146 153
The peak demand for the NSP System, PSCo and SPS all typically occurs in the summer. The 2000
system peak demand for the NSP System occurred on Aug. 14, 2000. The 2000 system peak demand for
PSCo occurred on Aug. 9, 2000. The 2000 system peak demand for SPS occurred on Aug. 3, 2000. The
system peak demand for the Cheyenne system occurs in the winter.
Xcel Energy’s utility subsidiaries expect to use the following resources to meet their net
dependable system capacity requirements: 1) Xcel Energy’s electric generating stations, 2) purchases
from other utilities, independent power producers and power marketers, 3) demand-side management
options and 4) phased expansion of existing generation at select power plants.
Xcel Energy’s electric utility subsidiaries have contractual arrangements to purchase power from
other utilities and nonregulated energy suppliers. Capacity, typically measured in kilowatts or
megawatts, is the measure of the rate at which a particular generating source produces electricity.
Energy, typically measured in kilowatt-hours or megawatt-hours, is a measure of the amount of
electricity produced from a particular generating source over a period of time. Purchase power
contracts typically provide for a charge for the capacity from a particular generating source and a
charge for the associated energy actually purchased from such generating source.
The utility subsidiaries of Xcel Energy also make short-term and non-firm purchases to replace
generation from company owned units that is unavailable due to maintenance and unplanned outages,
to provide each utility’s reserve obligation, to obtain energy at a lower cost than that which could be
produced by other resource options, including company owned generation and/or long-term purchase
power contracts, and for various other operating requirements.
NSP System Resource Plan
During 2000, NSP-Minnesota filed an electric resource plan for the NSP System with the MPUC
for the period 2000 to 2015. The plan describes how Xcel Energy intends to meet the energy needs of
the NSP System and includes an approximate schedule of the timing of resource solicitation to meet
such needs. The plan contains conservation programs to reduce the NSP System’s peak demand and
conserve overall electricity use, an approximate schedule of power purchase solicitations to meet
increasing demand and programs and plans to maintain the reliable operation of existing resources. In
summary, the plan:
• forecasts 1.6-percent annual growth in the NSP System’s energy and peak demand requirements;
• outlines NSP System’s demand side management and conservation programs;
• shows new capacity needs of up to 600 megawatts by 2005 and 4,200 megawatts by 2015;
• describes the programs for achieving the mandated renewable energy sources of 425 megawatts
of wind and 125 megawatts of biomass (NSP-Minnesota contracted for all 125 megawatts of
biomass energy, but 80 megawatts of wind energy remains to be contracted); and
• updates the status of spent nuclear fuel at the Prairie Island plant and describes how it can
continue to operate through the end of its license given different alternatives for storing spent
The resource plan proposes to satisfy the NSP System resource needs through the following energy
• continued use of existing generation facilities, including the repowering of Black Dog Units 1
• demand reduction of an additional 910 megawatts by 2015 through conservation and load
• 425 megawatts of wind energy and 125 megawatt of biomass energy under contract by 2002; and
• acquisition of competitively priced resources through competitive bidding.
The MPUC is currently reviewing this resource plan. Key issues are the amount of demand side
management investment, nuclear spent fuel storage and its impact on future resource needs and
assumptions made regarding unaccounted for operating costs of wind. NSP-Minnesota expects the
MPUC to issue an order about this resource plan in mid-2001.
PSCo Resource Plan
PSCo estimates it will purchase approximately 37 percent of its total electric system energy input
for 2001. Approximately 36 percent of the total system capacity for the summer 2001 system peak
demand for PSCo will be provided by purchased power.
To meet the demand and energy needs of the rapidly growing economy in Colorado, PSCo recently
completed a solicitation process that will add approximately 1,800 megawatts of resources to its system
over the 2002-2005 time period. PSCo expects that purchased capacity will continue to meet a
significant portion of system requirements at least through 2016.
Purchased Transmission Services
Xcel Energy’s electric utility subsidiaries have contractual arrangements with regional transmission
service providers to deliver power and energy to the subsidiaries’ native load customers (retail and
wholesale load obligations with terms of more than one year). Point-to-point transmission services
typically include a charge for the specific amount of transmission capacity being reserved, although
some agreements may base charges on the amount of metered energy delivered. Network transmission
services include a charge for the metered demand at the delivery point at the time of the provider’s
monthly transmission system peak, usually calculated as a 12-month rolling average.
Fuel Supply and Costs
The following tables present the delivered cost per million Btu of each category of fuel consumed
for electric generation, the percentage of total fuel requirements represented by each category of fuel
and the weighted average cost of all fuels during such years.
Coal* Nuclear Average
NSP System Generating Plants: Cost Percent Cost Percent Fuel Cost
2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1.11 60% $0.45 36% $0.91
1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.10 58% 0.48 38% 0.88
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.00 60% 0.47 35% 0.85
* Includes refuse-derived fuel and wood
Coal Gas Average
PSCo Generating Plants: Cost Percent Cost Percent Fuel Cost
2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.91 87% $3.97 13% $1.30
1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.90 92% 2.52 8% 1.04
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.93 95% 2.46 5% 1.00
Coal Gas Average
SPS Generating Plants: Cost Percent Cost Percent Fuel Cost
2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1.45 70% $4.23 30% $2.28
1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.41 70% 2.38 30% 1.70
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.60 67% 2.19 33% 1.80
NSP-Minnesota and NSP-Wisconsin
NSP-Minnesota and NSP-Wisconsin normally maintain between 20 and 40 days of coal inventory at
each plant site. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery
of up to 100 percent of 2001 coal requirements and up to 70 percent of their 2002 requirements. Coal
delivery may be subject to short-term interruptions or reductions due to transportation problems,
weather and availability of equipment.
NSP-Minnesota and NSP-Wisconsin expect that all of the coal they burn in 2001 will have a sulfur
content of less than 1 percent. NSP-Minnesota and NSP-Wisconsin have contracts for a maximum of
21.4 million tons of low-sulfur coal for the next two years. The contracts are with two Montana coal
suppliers and four Wyoming suppliers. NSP-Minnesota and NSP-Wisconsin could purchase
approximately 5 percent of their coal requirements in the spot market in 2001 and 45 percent of coal
requirements in 2002 if spot prices are more favorable than contracted prices.
Estimated coal requirements at NSP-Minnesota’s major coal-fired generating plants and the coal
supply for such requirements are approximately 12 million tons per year, which is covered by contracts
with expiration dates that vary between 2001 and 2003.
NSP-Minnesota and NSP-Wisconsin’s current fuel oil inventory is adequate and they have access to
additional spot purchase supplies to meet anticipated 2001 requirements. Additional oil may be
obtained through spot purchases.
To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for
uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract
strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium,
conversion and enrichment. Current contracts are flexible and cover 100 percent of uranium,
conversion and enrichment requirements through the year 2001. These contracts expire at varying times
between 2001 and 2005. The overlapping nature of contract commitments will allow NSP-Minnesota to
maintain 50 percent to 100 percent coverage beyond 2001. NSP-Minnesota expects sufficient uranium,
conversion and enrichment to be available for the total fuel requirements of its nuclear generating
plants. Fuel fabrication is 100 percent committed through 2004 and 30 percent committed through
PSCo’s primary fuel for its steam electric generating stations is low-sulfur western coal. PSCo’s
coal requirements are purchased primarily under seven long-term contracts with suppliers operating in
Colorado and Wyoming. During 2000, PSCo’s coal requirements for existing plants were approximately
9.9 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts.
Coal supply inventories at Dec. 31, 2000, were approximately 33 days usage, based on the average burn
rate for all of PSCo’s coal-fired plants.
PSCo operates the Hayden Station, and has partial ownership in the Craig Station, in Colorado.
All of Hayden Station’s generating requirements are supplied under a long-term agreement. More than
75 percent of PSCo’s Craig Station coal requirements are supplied under two long-term agreements.
Any remaining Craig Station requirements for PSCo are supplied via spot coal purchases.
PSCo has secured more than 75 percent of Cameo Station’s coal requirements for 2001 and 2002.
Any remaining requirements may be purchased from this contract or the spot market. PSCo has
contracted for long-term coal supplies to supply approximately 40 percent of the Cherokee and
Valmont Stations’ projected requirements in 2001. In addition, PSCo has contracted for substantially all
of Cherokee’s and Valmont’s remaining projected 2001 coal needs.
PSCo has long-term coal supply agreements for the Pawnee and Comanche Stations’ projected
requirements. Under the long-term agreements, the supplier has dedicated specific coal reserves at the
contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal
supply agreement to supply approximately 80 percent of Arapahoe Station’s projected requirements for
2001. Any remaining Arapahoe Station requirements will be procured via spot purchases.
PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and
certain boilers. Natural gas supplies for PSCo’s power plants are procured under short- and
intermediate-term contracts to provide an adequate supply of fuel.
SPS purchases all of its coal requirements for Harrington and Tolk electric generating stations
from TUCO Inc., in the form of crushed, ready-to burn coal delivered to SPS’ plant bunkers. For the
Harrington station the coal supply contract expires in 2016 and the coal-handling agreement expires in
2004. For the Tolk station, the coal supply contract expires in 2017 and the coal-handling agreement
expires in 2005. At Dec. 31, 2000, coal inventories at the Harrington and Tolk sites were approximately
30 and 32 days supply, respectively. TUCO has a long-term coal supply agreement to supply
approximately 55 percent of Harrington’s projected requirements in 2001. TUCO has long term
contracts for supply of coal in sufficient quantities to meet the primary needs of the Tolk station.
SPS has a number of short and intermediate contracts with natural gas suppliers operating in gas
fields with long life expectancies in or near its service area. SPS also utilizes firm and interruptible
transportation to minimize fuel costs during volatile market conditions and to provide reliability of
supply. SPS maintains sufficient gas supplies under short- and intermediate-term contracts to meet all
power plant requirements; however, due to flexible contract terms, approximately 55 percent of SPS’
gas requirements during 2000 were purchased under spot agreements.
Nuclear Power Operations and Waste Disposal
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island
plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1
and 2 began operation in 1973 and 1974 and are licensed to operate until 2013 and 2014, respectively.
Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge
and handling of such wastes are controlled by federal regulation. High-level radioactive waste includes
used nuclear fuel. Low-level radioactive waste consists primarily of demineralizer resins, paper,
protective clothing, rags, tools and equipment that has become contaminated through use in the plant.
Federal law places responsibility on each state for disposal of its low-level radioactive waste.
Low-level radioactive waste from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is
currently disposed of at the Barnwell facility, located in South Carolina (all classes of low-level waste),
and the Clive facility, located in Utah (class A low-level waste only). Chem Nuclear is the owner and
operator of the Barnwell facility, which has been given authorization by South Carolina to accept
low-level radioactive waste from out of state. Envirocare, Inc. operates the Clive facility.
NSP-Minnesota and Barnwell currently operate under an annual contract, while NSP-Minnesota uses
the Envirocare facility through various low-level waste processors. NSP-Minnesota has low-level storage
capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to
operate until the end of their licensed life, if off-site low-level disposal facilities were not available to
The federal government has the responsibility to dispose of, or permanently store, domestic spent
nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the
Department of Energy (DOE) to implement a program for nuclear waste management. This includes
the siting, licensing, construction and operation of a repository for domestically produced spent nuclear
fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent storage
or disposal facility by 1998. None of NSP-Minnesota’s spent nuclear fuel has yet been accepted by the
DOE for disposal. See Item 3—Legal Proceedings and Note 15 to the Financial Statements under Item
8 for further discussion of this matter.
NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island
nuclear plants. NSP-Minnesota has expanded the used nuclear fuel storage facilities at its Monticello
plant by replacement of the racks in the storage pool and by shipping 1,058 used fuel assemblies to a
General Electric storage facility. The Monticello plant is expected to have sufficient pool storage
capacity to the end of its current operating license in 2010.
The Prairie Island spent fuel pool has undergone two storage rack replacements. The on-site
storage pool for spent nuclear fuel at Prairie Island was nearly filled and adequate space was no longer
available. In 1994, a Minnesota law was enacted authorizing NSP-Minnesota to install 17 spent fuel
casks for storage of spent nuclear fuel at Prairie Island. NSP-Minnesota has determined 17 casks will
allow facility operation until 2007. As of Dec. 31, 2000, 12 storage casks were loaded and stored on the
Prairie Island nuclear generating plant site. The Minnesota Legislature established several energy
resource requirements and other commitments for NSP-Minnesota to obtain the Prairie Island
temporary nuclear fuel storage facility approval. NSP-Minnesota has implemented programs to meet
the legislative commitments.
NSP-Minnesota is part of a consortium of private parties working to establish a private facility for
interim storage of spent nuclear fuel. In 1997, Private Fuel Storage LLC (PFS) filed a license
application with the Nuclear Regulatory Commission (NRC) for a national temporary storage site for
spent nuclear fuel. The PFS will undertake the development, licensing, construction and operation of a
storage facility on the Skull Valley Indian Reservation in Utah. The NRC license review process
consists of formal evidentiary hearings and opportunity for public input. Storage cask certification
efforts are continuing, with one cask vendor on track to meet the project goals. The interim used fuel
storage facility could be operational and able to accept the first shipment of spent nuclear fuel by 2004.
However, due to uncertainty regarding regulatory and governmental approvals, it is possible that this
interim storage may be delayed or not available at all.
In March 2001, NSP-Minnesota signed a contract with Steam Generator Team Ltd. to perform
engineering and construction services for the installation of replacement generators at the Prairie Island
nuclear power plant. NSP-Minnesota is evaluating the economics of replacing two 25-year-old steam
generators on unit 1 at the plant. NSP-Minnesota is taking steps to preserve the replacement option for
as early as 2004. The total cost of replacing the steam generators is estimated to be approximately
The NRC has issued a number of regulations, bulletins and orders that require analyses,
modification and additional equipment at commercial nuclear power plants. The NRC is engaged in
various ongoing studies and rulemaking activities that may impose additional requirements upon
commercial nuclear power plants. Management is unable to predict any new requirements or their
impact on NSP-Minnesota’s facilities and operations.
Nuclear Management Company (NMC)
During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. and
Alliant Energy established the NMC. The four companies operate seven nuclear units at five sites, with
a total generation capacity exceeding 3,650 megawatts.
During the second quarter of 2000, the Nuclear Regulatory Commission (NRC) approved requests
by NMC’s four affiliated utilities to transfer operating authority for their five nuclear plants to NMC.
NMC responsibilities will include oversight of on-site dry storage facilities for used nuclear fuel at the
Point Beach and Prairie Island nuclear plants. Utility plant owners will continue to own the plants,
control all energy produced by the plants and retain responsibility for nuclear liability insurance and
decommissioning costs. Existing personnel will continue to provide day-to-day plant operations, with the
additional benefit of tapping into ideas from all NMC-operated plants for improved safety, reliability
and operational performance.
During the third quarter of 2000, NMC and Consumers Energy (CE) reached an agreement for
the NMC to operate CE’s 789-megawatt Palisades nuclear plant in Covert, Mich. The addition of
Palisades gives NMC 4,500 megawatts of generation, making it the sixth largest operator of nuclear
plants in the United States.
For further discussion of nuclear issues, see Note 14 and Note 15 to the Financial Statements
under Item 8.
interconnections directly with, and the purchase of gas directly from, interstate pipelines, thereby
avoiding the delivery charges added by the local gas utility. The gas utility subsidiaries of Xcel Energy
have and will continue to aggressively pursue the retention of all customers on their systems.
NSP-Minnesota and NSP-Wisconsin provide unbundled transportation service to large customers.
Transportation service does not have an adverse effect on earnings because NSP-Minnesota and
NSP-Wisconsin’s sales and transportation rates have been designed to make NSP-Minnesota and
NSP-Wisconsin economically indifferent to whether gas has been sold and transported or merely
transported. However, some transportation customers may have greater opportunities or incentives to
physically bypass the LDC distribution system.
PSCo provides unbundled transportation service to large customers. and has participated fully in
state regulatory and legislative efforts to develop a framework for extending unbundling down to the
residential and small commercial level. PSCo supported a gas unbundling bill, passed by the Colorado
Legislature in 1999, that provides the CPUC the authority and responsibility to approve voluntary
unbundling plans submitted by Colorado gas utilities in the future. PSCo has not filed a plan to open
its natural gas supply business to competition and continues to evaluate its business opportunities for
PSCo and Cheyenne extend and operate their distribution systems primarily by virtue of
non-exclusive franchises granted by the various cities and towns. Their respective state commissions
approve such franchise agreements. Because the franchises are non-exclusive, PSCo and Cheyenne can
be faced with the threat of intrusion into their gas territory by third parties. PSCo holds territorial
certificates for a portion of their gas service territory, giving them the exclusive right to extend their
distribution system and provide natural gas sales and transportation service. However, for the majority
of their gas service territory, no such territorial certificates exist. PSCo has filed with the CPUC an
application to certify its gas service territory along the front range of Colorado. PSCo is pursuing
settlement negotiations and expects a resolution during 2001.
Capability and Demand
NSP-Minnesota and NSP-Wisconsin
Xcel Energy categorizes its gas supply requirements as firm or interruptible (customers with an
alternate energy supply). The maximum daily sendout (firm and interruptible) for the combined system
of NSP-Minnesota and NSP-Wisconsin was 730,026 mmBtu for 2000, which occurred on Dec. 11, 2000.
NSP-Minnesota and NSP-Wisconsin purchase gas from independent suppliers. The gas is delivered
under gas transportation agreements with interstate pipelines. These agreements provide for firm
deliverable pipeline capacity of approximately 630,000 mmBtu/day. In addition, NSP-Minnesota and
NSP-Wisconsin have contracted with providers of underground natural gas storage services. Using
storage reduces the need for firm pipeline capacity. These storage agreements provide storage for
approximately 16 percent of annual and 23 percent of peak daily, firm requirements of NSP-Minnesota
NSP-Minnesota and NSP-Wisconsin also own and operate two liquified natural gas (LNG) plants
with a storage capacity of 2.5 bcf equivalent and four propane-air plants with a storage capacity of 1.4
bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production
capacity equivalent to 246,000 mcf of natural gas per day, or approximately 32 percent of peak day firm
requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline
transportation charges to meet the peaks caused by firm space heating demand on extremely cold
winter days and can be used to minimize daily imbalance fees on interstate pipelines.
Gas utilities in Minnesota are required to file for a change in gas supply contract levels to meet
peak demand, to redistribute demand costs among classes, or exchange one form of demand for
another. In July 2000, the MPUC approved NSP’s 1999-2000 entitlement levels, which allow
NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation
and storage levels in its monthly PGA. NSP-Minnesota’s filing for approval of its 2000-2001 entitlement
levels is pending MPUC action.
PSCo and Cheyenne
PSCo and Cheyenne project peak day gas supply requirements for firm sales and backup
transportation (transportation customers contracting for firm supply backup) to be 1,639,899 mmBtu. In
addition, firm transportation customers hold 379,882 mmBtu of capacity without supply backup. Total
firm delivery obligations for PSCo and Cheyenne are 2,019,781 mmBtu per day. The maximum daily
deliveries for both companies for 2000 (firm and interruptible services) were 1,612,589 mmBtu on
Dec. 11, 2000.
PSCo and Cheyenne purchase gas from independent suppliers. The gas supplies are delivered to
the respective delivery systems through a combination of transportation agreements with interstate
pipelines and deliveries by suppliers directly to each company. These agreements provide for firm
deliverable pipeline capacity of 1,193,821 mmBtu/day, which includes 731,960 mmBtu of supplies held
under third-party storage agreements. In addition, PSCo operates three company-owned storage
facilities, which provide about 147,980 mmBtu of gas supplies on a peak day. The balance of the
quantities required to meet firm peak day sales obligations are primarily purchased at the companies’
citygate meter stations and a small amount received directly from wellhead sources.
PSCo has received approval to abandon one if its three storage facilities, Leyden Storage Field,
beginning October 2001. The field’s 110,000 mmBtu peak day capacity will be replaced in 2001 with
additional third-party storage and transportation capacity.
PSCo is required by CPUC regulations to file a gas purchase plan by June of each year projecting
and describing the quantities of gas supplies, upstream services and the costs of those supplies and
services for the period beginning July 1 through June 30 of the following year. PSCo is also required to
file a gas purchase report by October of each year reporting actual quantities and costs incurred for gas
supplies and upstream services for the 12-month period ending the previous June 30. PSCo has filed
the required Plans with the CPUC, which is reviewing the gas purchase report for the period July 1,
1999, through June 30, 2000.
Gas Supply and Costs
Xcel Energy’s gas utilities actively seek gas supply, transportation and storage alternatives to yield
a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and
economical rates. This diversification involves numerous domestic and Canadian supply sources, with
varied contract lengths.
The following table summarizes the average cost per mmBtu of gas purchased for resale by Xcel
Energy’s regulated retail gas distribution business.
NSP-Minnesota NSP-Wisconsin PSCo Cheyenne
2000 . . . . . . . . . . . . . . . . . . . . . . . . $4.56 $4.71 $4.48 $4.03
1999 . . . . . . . . . . . . . . . . . . . . . . . . $2.97 $3.32 $2.85 $2.57
1998 . . . . . . . . . . . . . . . . . . . . . . . . $2.83 $3.18 $2.64 $2.45
The cost of gas supply, transportation service and storage service is recovered through various cost
recovery adjustment mechanisms.
NSP-Minnesota and NSP-Wisconsin
NSP-Minnesota and NSP-Wisconsin have firm gas transportation contracts with several pipelines,
which expire in various years from 2001 through 2013. Approximately 80 percent of NSP-Minnesota
and NSP-Wisconsin’s retail gas customers are served from the Northern Natural pipeline system.
In addition to fixed transportation charge obligations, NSP-Minnesota and NSP-Wisconsin have
entered into firm gas supply agreements that provide for the payment of monthly or annual reservation
charges irrespective of the volume of gas purchased. The total annual obligation is approximately
$18 million. These agreements allow NSP-Minnesota and NSP-Wisconsin to purchase natural gas at a
high load factor at rates below the prevailing market price, reducing the total cost per mmBtu.
NSP-Minnesota and NSP-Wisconsin have certain gas supply and transportation agreements that
include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in
lieu of delivery. At Dec. 31, 2000, NSP-Minnesota and NSP-Wisconsin were committed to approximately
$221 million in such obligations under these contracts, which range from the years 2001-2013.
NSP-Minnesota and NSP-Wisconsin have negotiated market out clauses in their new supply agreements,
which reduce purchase obligations if NSP-Minnesota and NSP-Wisconsin no longer provide merchant
NSP-Minnesota and NSP-Wisconsin purchase firm gas supply from approximately 30 domestic and
Canadian suppliers under contracts with durations of one year to 10 years. NSP-Minnesota and
NSP-Wisconsin purchase no more than 20 percent of their total daily supply from any single supplier.
This diversity of suppliers and contract lengths allows NSP-Minnesota and NSP-Wisconsin to maintain
competition from suppliers and minimize supply costs.
NSP-Minnesota and NSP-Wisconsin have completed substantially all of their obligations related to
gas supply transportation and storage contracts that resulted from FERC Order 636.
PSCo and Cheyenne
PSCo and Cheyenne have attempted to maintain low-cost, reliable natural gas supplies by
optimizing a balance of long-term and short-term gas purchases, firm transportation and gas storage
contracts. During 2000, PSCo and Cheyenne purchased natural gas from approximately 47 suppliers.
PSCo and Cheyenne have completed substantially all of their obligations related to gas supply
transportation and storage contracts that resulted from FERC Order 636. PSCo and Cheyenne have
entered into new contracts for firm transportation and gas storage services. Adequate supplies of
natural gas are currently available for delivery within the region. PSCo and Cheyenne continually
evaluate the natural gas markets and procure supplies, as needed, to meet current and anticipated
During 1999, Viking, WICOR and CMS Energy Corp. announced plans to build an interstate
natural gas pipeline to serve the growing needs of the northern Illinois and southeastern Wisconsin
markets. The three energy companies each own an equal share of the pipeline. The project, called the
Guardian Pipeline, will transport natural gas from a hub near Joliet, Ill. to the Ixonia, Wis., area. In
March 2001, the FERC issued a certificate of public convenience and necessity authorizing the
construction and operation of the Guardian pipeline. The estimated cost of the 147-mile pipeline is
$230 million and is expected to be in operation by late 2002.
Gas Operating Statistics (Xcel Energy)
Year Ended Dec. 31,
2000 1999 1998
Gas Deliveries (Thousands of Dth):
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137,989 125,694 121,674
Commercial and Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . 96,370 91,064 89,203
Total Retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 234,359 216,758 210,877
Transportation and Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 297,041 272,757 276,656
Total Deliveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 531,400 489,515 487,533
Number of Customers at End of Period:
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,483,114 1,436,455 1,388,933
Commercial and Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . 143,568 146,090 138,077
Total Retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,626,682 1,582,545 1,527,010
Transportation and Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,233 3,152 2,796
Total Customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,629,915 1,585,697 1,529,806
Gas Revenues (Thousands of Dollars):
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 878,638 $ 691,612 $ 662,073
Commercial and Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . 506,040 375,814 367,213
Total Retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,384,678 1,067,426 1,029,286
Transportation and Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 84,202 74,003 80,718
Total Gas Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,468,880 $1,141,429 $1,110,004
Dth Sales per Retail Customer ......................... 144.07 136.97 138.09
Revenue per Retail Customer . ......................... $ 851.23 $ 674.50 $ 674.05
Average Revenue per Dth:
Residential . . . . . . . . . . . . . ......................... $ 6.37 $ 5.50 $ 5.44
Commercial and Industrial . ......................... $ 5.25 $ 4.13 $ 4.12
Transportation and Other . . ......................... $ 0.28 $ 0.27 $ 0.29